Traditionally, a drilling operator utilizes one or more Measurement-while-drilling (hereinafter “MWD”) tools and/or instruments and/or one or more Logging-while-drilling (hereinafter “LWD”) tools and/or instruments (hereinafter “wellbore instruments”) to provide control over construction and/or drilling of a wellbore. The wellbore instruments may provide the drilling operator with information regarding one or more conditions at a bottom of a wellbore substantially in real time as the wellbore is being drilled by a drill bit. To successfully and accurately construct and/or drill a well with the drill bit, the drilling operator may depend on the information obtainable from the bottom of the wellbore which may be provided in real time via the MWD and/or LWD tools and/or instruments.
The information provided by the MWD and/or LWD tools and/or instruments may include and/or may be based on one or more directional measurements, drilling-related measurements and/or directional drilling variables such as inclination and/or direction (azimuth) of the drill bit, and geological formation data and/or measurements, such as, for example, natural gamma ray radiation levels and electrical resistivity of the rock formation and/or the like.
In embodiments, the MWD tools and/or instruments may include one or more of the following types of measuring devices: a weight-on-bit measuring device; a torque measuring device; a vibration measuring device; a shock measuring device; a stick slip measuring device; a direction measuring device; an inclination measuring device; a gamma ray measuring device; a directional survey device; a tool face device; a borehole pressure measuring device; and/or a temperature device. The one or more MWD tools may detect, collect and/or log data and/or information about the conditions at the drill bit, around the formation, at a front of the drill string and/or at a distance around the drill strings. The one or more MWD tools may provide telemetry for operating rotary steering tools. It should be understood that the one or more MWD tools may be any type of MWD tools as known to one of ordinary skill in the art.
The LWD tools and/or instruments may include one or more of the following types of logging and/or measuring devices: a resistivity measuring device; a directional resistivity measuring device; a sonic measuring device; a nuclear measuring device; a nuclear magnetic resonance measuring device; a pressure measuring device; a seismic measuring device; an imaging device; a formation sampling device; a gamma ray measuring device; a density and photoelectric measuring device; a neutron porosity device; a bit resistivity measuring device, a ring resistivity measuring device, a button resistivity measuring device and/or a borehole caliper device. In an embodiment, the LWD tool may include, for example, a compensated density neutron tool, an azimuthal density neutron tool, a resistivity-at-the-bit tool, hookload sensor and/or a heave motion sensor. It should be understood that the LWD tools may be any type of LWD tools as known to one or ordinary skill in the skill.
Often wellbore instruments may be integrated into a single instrument package which may be referred to as MWD/LWD tools. In the description which follows, the term “MWD system” will be used collectively to refer to MWD, LWD, and/or a combination MWD/LWD tools and/or instruments. The term MWD system should also be understood to encompass equipment and/or techniques for data transmission from within the well to the earth's surface as known to one of ordinary skill in the art.
The MWD system may measure and acquire one or more parameters within the wellbore, and may transmit the acquired data measured by the MWD system to the earth's surface from within the wellbore. Traditionally, several different methods for transmitting data to the surface may be provided and, often, may include mud pulse telemetry. In mud-pulse telemetry, the acquired data may be transmitted from the MWD system in the wellbore to the surface by means of generating pressure waves in drilling fluid, such as, for example, which may be pumped through a drill string by pumps on the surface. The pressure waves in the drilling fluid may be produced or generated by the one or more components in of mud-pulse telemetry system as known to one of ordinary skill in the art.
One or more pressure transducers may be located on a standpipe at the earth's surface and generate one or more signals representative of variations in a pressure associated with the drilling fluid. As a result, the transducers may detect the one or more telemetry pressure waves and/or generate one or more signals which may represent one or more variations in the pressure associated with the drilling fluid generated by the one or more telemetry pressure waves. A digital signal processing receiver may detect the one or more signals generated by the transducers to recover the one or more symbols associated with the telemetry pressure waves and send data data from the one or more symbols to a central processing unit. The CPU 64 may generate information based on the data recovered from the one or more symbols which may be accessible by the drilling operator for constructing and/or drilling of a wellbore.
However, the telemetry pressure wave may be subjected to attenuation, reflections, and/or noise as the telemetry pressure wave moves through the drilling fluid. The telemetry pressure waves may also be reflected or partial reflected off the bottom of the wellbore or at one or more acoustic impedance mismatches in the drill string and a surface drilling fluid system. The one or more components of a surface drilling fluid system, such as, for example, a mud pump may generate noise which may interfere telemetry pressure waves. The result of the attenuation, reflections and noise may prevent the digital signal processing receiver from accurately recovering the one or more symbols associated with the telemetry pressure waves.
Historically, the digital signal processing receiver exhibits may slightly reduce or fail to reduce the occurrences of double bit errors due to differential encoding and/or may fail to exhibit increases in resolution and accuracy of the bit confidence of each bit and fails to reduce occurrences of double bit errors. As a result, the digital signal processing receiver fails to filter out incorrect and/or questionable symbols and/or does not reduce errors from being included into logs based on the telemetry pressure waves.
Thus, the receivers, systems and methods for identifying decoded signals are necessary in order to (1) provide improved overall performance, resolution and accuracy of the bit confidence of each bit, (2) prevent occurrences of double bit errors due to differential encoding, (3) filter out all or substantially all incorrect and/or questionable symbols and/or data points, and (4) prevent all or substantially all errors from being included into logs generated by the receivers, systems and/or methods. As a result, the receivers, systems and methods for identifying decoded signals advantageously decreases double symbol errors and/or bit errors which results in an advantageously lower bit error rate (hereinafter “BER”).